Acid gas removal from gas streams, particularly removal of hydrogen sulfide and carbon dioxide from gas streams formed in refinery process units, synthesis gas production plants and oil and gas production facilities, is necessary to allow this gas to be used and/or sold into pipeline systems. The removal of sulfur compounds from these acid gasses or “sour gasses” is called “sweetening.” Typically, acid gases are removed using an amine-based solvent to absorb the acid gas via various chemical reactions, resulting in the production of a rich amine solvent, which can then be regenerated using heat.
Hydrogen sulfide is a toxic gas that must generally be removed to extreme low concentrations (less than 0.25 grains of H2S per 100 standard cubic feet) prior to pipeline delivery. When mixed with free water it forms a weak acid that can cause corrosion.
Carbon dioxide is a non-toxic inert gas. Carbon dioxide, as such, is harmless in dry natural gas but when mixed with free water will form a weak acid and also cause corrosion. Inlet gas to cryogenic plants that contain concentrations of CO2 in excess of 0.75 to 1.0 percent CO2 may cause freezing problems. The CO2 will freeze to a solid ice in a turbo expander plant demethanizer where it may plug lines and even plug the tower itself. Often flooding of the demethanizer results from carbon dioxide freezing within the tower. When the plant inlet gas contains concentrations of carbon dioxide too high to process, all of the gas may be treated or part of the gas may be separated into a side stream and treated by an amine plant. Principally all the carbon dioxide is removed in the amine plant. When the side stream is processed, and sufficient gas is treated, it is blended back with the untreated gas, thus yielding a carbon dioxide content of the blended stream which is low enough for processing. Carbon dioxide also lowers the heating value of the gas stream which is usually specified as 1000 BTU/scf.
There are generally two types of gas treating processes: (a) absorption and (b) adsorption. In absorption processes, the gas stream contacts a liquid that selectively removes acid gases. The most common absorption process is the amine process. The liquid absorbent is a mixture of water and a chemical amine, usually monoethanol-amine (MEA) or diethanolamine (DEA). Sometimes triethanol-amine (TEA), diglycolamine (DGA), and methyl-diethanolamine (MDEA), diisopropylamine, sulfanol and solutions of these, with special additives to improve efficiencies, are utilized.
Amines remove carbon dioxide and hydrogen sulfide by a chemical reaction that changes the chemical form of both the amine and the acid gases. The new chemical changes the acid gases to a liquid form which is separated from the acid-free gas or sweetened gas. The chemical reaction between amine (called lean amine at the start of the process) and acid gases gives off heat when the reaction takes place. The sweet residue gas flows out the top of a contactor or absorber and the reacted amine (also called rich amine) flows out the bottom and is generally higher in temperature than the inlets. Lean amine is regenerated by reducing the pressure and adding heat to the rich amine.
The “Fifth Edition Gas Purification” by Arthur Kohl and Richard Nielsen (Gulf Publishing, 1960 to 1997) illustrates various processes for the purification of gases utilizing amine solvents and illustrates processes for regeneration of the amine solvents. Particularly preferred amine-based solvents include secondary and tertiary amines (e.g., diethanolamine [DEA], and/or methyldiethanolamine [MDEA]), which are generally more energy efficient than primary amines due to their lower heat of reaction and lower energy requirements for regeneration. Alternative amine solvents may further include monoethanolamine [MEA], diglycolamine [DGA], triethanolamine [TEA], diisopropylamine, and various combinations thereof, along with one or more additives.
The effectiveness of a particular amine solvent to absorb acid gases to meet the treated gas specification typically depends on the residual acid gas content in the lean amine, which in turn is a function of the particular regeneration method and conditions. The lower the acid gas content in the lean amine, the more effective the acid gas absorption process. Therefore, a variety of approaches have been undertaken to improve the current acid gas absorption and regeneration processes.
While numerous prior art processes and systems for acid gas absorption and solvent regeneration are known in the art, many suffer from one or more disadvantages or inefficiencies.